This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Field Of The Invention
The present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the present invention relates to a pneumatic compression system to support artificial lift for a wellbore, and methods for optimizing pumping speed for a pneumatic pumping unit to control the lift of production fluids to the surface.
Technology In The Field Of The Invention
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing.
In completing a wellbore, it is common for the drilling company to place a series of casing strings having progressively smaller outer diameters into the wellbore. These include a string of surface casing, at least one intermediate string of casing, and a production casing. The process of drilling and then cementing progressively smaller strings of casing is repeated until the well has reached total depth. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface. The final string of casing, referred to as a production casing, is also typically cemented into place.
To prepare the wellbore for the production of hydrocarbon fluids, a string of production tubing is run into the casing. The production tubing serves as a conduit for carrying production fluids to the surface. A packer is optionally set at a lower end of the production tubing to seal an annular area formed between the tubing and the surrounding strings of casing.
In order to carry the hydrocarbon fluids to the surface, a pump may be placed at a lower end of the production tubing. This is known as “artificial lift.” In some cases, the pump may be an electrical submersible pump, or ESP. ESP's utilize a hermetically sealed motor that drives a multi-stage pump. More conventionally, oil wells undergoing artificial lift use a downhole reciprocating plunger-type of pump. The reciprocating downhole pump is relatively long and thin to avoid restricting oil flow up the well. The pump has one or more valves that capture fluid on a downstroke, and then lift the fluid on the upstroke. This is known as “positive displacement.” In some designs such as that disclosed in U.S. Pat. No. 7,445,435, the pump may be able to both capture fluid and lift fluid on each of the downstroke and the upstroke.
Conventional positive displacement pumps have a barrel that is reciprocated at the end of a “rod string.” The rod string comprises a series of long, thin joints of pipe that are threadedly connected through couplings. The rod string is pivotally attached to a pumping unit at the surface. The rod string moves up and down within the production tubing to incrementally lift production fluids from subsurface intervals to the surface.
Most pumping units on land are so-called rocking beam drive units. Rocking beam units typically employ electric motors or internal combustion engines having a rotating drive shaft. The shaft turns a crank arm, or possibly a pair of crank arms. The crank arms, in turn, have heavy, counter-weighted flywheels. The flywheels rotate along with the crank arms and provide weighted leverage for lifting the rod string. Rocking beam units also have a so-called walking beam that pivots over a fulcrum. One end of the walking beam is mechanically connected to the crank arms. As the crank arms and flywheels rotate, they cause the walking beam to reciprocate up and down over the fulcrum.
The opposite end of the walking beam is a so-called horse head. The horse head is positioned over the wellhead at the surface. As the walking beam is reciprocated, the horse head cycles up and down over the wellbore. This, in turn, translates the rod and attached pump up and down within the wellbore. A drawing and further description of a walking beam unit are provided in U.S. Pat. No. 7,500,390, which is incorporated herein in its entirety by reference.
Another type of pumping unit is a hydraulic actuator system. These systems employ an elongated cylinder residing over a wellbore. The cylinder is axially aligned with the wellbore and holds a reciprocating piston. The cylinder cyclically receives fluid pressure through an oil line. As fluid is injected through the oil line and into the cylinder, the piston is caused to move linearly within the cylinder. This, in turn raises the connected rod string, causing the pump to undergo an upstroke. When fluid pressure is released from the cylinder, the rod string is lowered due to gravitational forces, causing the downhole pump to undergo a downstroke. Oil is returned to a reservoir, or pressure tank, and is then pumped back into the cylinder for the next upstroke.
A similar but much less common system is a pneumatic pumping system. These systems also employ a cylinder residing over a wellbore. The cylinder is axially aligned with the wellbore and also holds a reciprocating piston. In this arrangement, the piston is reciprocated up and down through the cyclical injection of a working gas (such as air) against the piston on the upstroke, and the bleeding of the working gas from the cylinder in the downstroke. In the case of air, the air is just vented to the atmosphere.
Pneumatic pumping systems have an advantage over hydraulic pumping systems in that they do not require an oil reservoir, a cooler, or elaborate valving. Pneumatic systems have traditionally required only a compressor, a timer and a large supply of warm gas. However, pneumatic systems have been used with simple shallow wells and have not been provided with intelligence that controls pumping speed.
Therefore, a need exists for a pneumatic pumping system that offers a controller that controls pump cycle time and pumping speed. In addition, a need exists for a pumping system that is able to vary upstroke speed and downstroke speed by controlling the rate at which a working gas is pumped from a high pressure tank and into a cylinder, and then released from the cylinder and into a low pressure tank as part of a closed loop system.